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ABSTRACT This paper presents an overview of the factors involved in the selection of an active souring management solution for the Mars field, at which waterflood operations are due to commence in March 2004. It is well documented that the majority of similar seawater injection applications have experienced increased down-hole sulfate-reducing bacteria activity and the reservoir souring and H2S control difficulties associated with this. The Mars field was initially commissioned in 1996 with non-NACE MR0175 compliant materials used for well tubing and casing. Following detailed reservoir modeling, and HSE Risk Assessment, a plan was developed to change-out all production tubing to NACE materials, and a 100 % redundant H2S monitoring system was installed. However, replacement of production casing materials was cost prohibitive so a plan was developed to mitigate the predicted levels of souring by the use of an active souring control approach. Investigation into the various alternatives available, including sulfate removal membranes, biocide treatment and nitrate or nitrite injection, has determined that nitrate injection is likely to be the most effective souring prevention tool. INTRODUCTION The Mars field in the Gulf of Mexico has been producing since 1996 via a Tension-Leg Platform (TLP) host, located approximately 130 miles South East of New Orleans and moored in 3000ft of water. In order to prevent sand compaction and maintain high levels of production in the coming years it has become necessary to waterflood the reservoir. Due to the lack of a local aquifer and the distance of the TLP from shore, the only viable option has been to use a seawater flood injecting directly into the oil leg. The maximum output of the present injection system is 90,000 barrels of water per day (BWPD), although provision has been made for this to be increased to 130,000 BWPD later in the field life if this proves necessary. It is well known that waterflood operations, undertaken with the aim of prolonging field life and increasing ultimate hydrocarbon recovery levels, often lead to souring of reservoirs as a consequence of the activity of sulfatereducing bacteria (SRB) within the reservoir being stimulated by seawater injection (1). Souring can increase production costs due to the requirement for the use of sour service materials, the need for chemical treatments to reduce H2S to acceptable levels, the generation and consequences of iron sulfide scaling, increased corrosion rates, health and safety considerations and, potentially, the shutting-in of affected wells. A management of change (MOC) was issued in June 1995 documenting a change to P110 and CYP-110 sweet service casing for the production strings from NACE MR0175 compliant (2) C100 sour service materials on the grounds of a cost saving and on the basis that sulfate removal membranes would become a viable technology. It is this decision to specify non-H2S tolerant materials downhole that has subsequently shaped the requirement for the work considered in this document. This work has been performed in order to assess the uncertainties involved in the prediction of the future extent of reservoir souring and, ultimately, to develop an active souring management plan to allow continued production in a situation where the reservoir will have a propensity to sour following the commencement of waterflood operations. A comprehensive study to determine the H2S exposure limits of the existing production metallurgy has resulted in the replacement of production tubing strings and their associated components. However, the original well casing is still in place due to the prohibitive cost of fully recompleting the
- North America > United States > Gulf of Mexico > Central GOM (0.75)
- North America > United States > Louisiana > Orleans Parish > New Orleans (0.24)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.68)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Mississippi Canyon > Block 851 > Mars Field (0.99)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Mississippi Canyon > Block 850 > Mars Field (0.99)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Mississippi Canyon > Block 808 > Mars Field (0.99)
- (12 more...)
The Application of Bioassays for Evaluating In-Situ Biocide Efficiency in Offshore Oil Production in the North Sea
Larsen, Jan (Maersk FPSOs) | Hansen, Lars Hvejsel (Maersk Olie og Gas AS) | Jensen, Michael (Maersk Oil) | Thomsen, Uffe Sognstrup (Danish Technological Institute) | Sorensen, Ketil (Danish Technological Institute) | Lundgaard, Thomas (Danish Technological Institute) | Skovhus, Torben Lund (Danish Technological Institute)
Abstract Microbial activity has a severe impact on corrosion of oil production facilities and reservoir souring. Bacterial growth and metabolic products significantly aggravating the corrosion of pipelines, manifolds, and separators which increases the risk of system failure. Microbiologically influenced corrosion (MIC) is caused by the turnover of hydrogen, sulfur and organic carbon driven by sulfate-reducing bacteria (SRB), sulfate-reducing Archaea (SRA) and methanogens. One important risk management tool is biocide dosage to control microbial activity in offshore oil production systems. To obtain a cost-efficient biocide treatment strategy it is important to determine biocide efficiency using microbiological assays (bioassays) that comprise quantitative measures of:Bacterial growth. Activity of specific bacterial groups related to MIC and souring. Accumulation rates of carbon dioxide, sulfide and methane. The bioassays presented in this paper investigate microbial activity in produced waters from an offshore platform where different biocides were tested. Based on molecular microbiology methods (MMM) it was evident that bacterial growth occurred in production water without addition of biocide at growth rates up to 0.46 1/d. Furthermore, active growth of both SRB and Archaea indicated that microorganisms that may be involved in corrosion processes were active in cell numbers of 10 cells/mL. Concurrently, depletion of sulfate and accumulation of total inorganic carbon, sulfide, and methane due to microbial activity was measured and maximum rates were used in combination with MMM to evaluate activity in bioassays with and without biocide. The results showed that addition of biocide in both injection and production waters decrease cell numbers and metabolic activity of SRB and methanogens. In general bioassay results can be used to evaluate the efficiency of biocides and nitrate at different dosage concentrations. The bioassays are most valuable when implemented in a risk assessment model for MIC and souring of oilfield reservoirs.
- North America > United States (0.94)
- Europe > Denmark > North Sea (0.65)
- Europe > United Kingdom > North Sea (0.41)
- (2 more...)
- Water & Waste Management > Water Management > Constituents > Treated Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Europe > Denmark > North Sea > Danish Sector > Central Graben > Block 5505/13 > Halfdan Field > Maastrichtian Formation (0.99)
- Europe > Denmark > North Sea > Danish Sector > Central Graben > Block 5505/13 > Halfdan Field > Danian Formation (0.99)
- Europe > Denmark > North Sea > Danish Sector > Central Graben > Block 5504/16 > Halfdan Field > Maastrichtian Formation (0.99)
- Europe > Denmark > North Sea > Danish Sector > Central Graben > Block 5504/16 > Halfdan Field > Danian Formation (0.99)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology (1.00)
- Management > Risk Management and Decision-Making (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
Abstract The activity of sulfate-reducing bacteria (SRB) has long been a major concern in oilfield water systems and petroleum reservoirs because these microorganisms are one of the main causative agents of microbial-influenced corrosion (MIC) as well as reservoir souring. Calcium nitrate and sodium nitrate treatments have gained popularity in recent years as alternatives or supplements to conventional biocide treatments. The object of these nitrate treatments is the suppression of SRB activity by the selective manipulation of indigenous bacteria. The treatments have met with mixed success; in some cases SRB activity has been suppressed, whereas in other cases the treatment has failed. Cases where nitrate treatment has not been successful are less likely to be publicized than cases where the treatment has been deemed to be successful. There are also instances where nitrate treatment has been successful in suppression of SRB activity but has given rise to unacceptable increases in corrosion rates in water injection pipe-work. In the experience of the author, nitrate treatments are rarely planned, trialed or implemented in a systematic manner, so as to maximize the chance of success and minimize unforeseen negative consequences. Based on practical examples from the author's experience and published information, this paper examines the most important factors that should be taken into account in methodical planning of trials and field-wide implementation of nitrate treatments, with particular reference to corrosion control.
- Europe > United Kingdom (0.68)
- Europe > Norway (0.68)
- North America > United States > Texas (0.47)
- Europe > Denmark > North Sea > Danish Sector (0.28)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.35)
- Europe > Norway > Norwegian Sea > Halten Terrace > Block 6407/9 > Draugen Field > Rogn Formation (0.99)
- Europe > Norway > Norwegian Sea > Halten Terrace > Block 6407/9 > Draugen Field > Garn Formation (0.99)
- Europe > Norway > Norwegian Sea > Halten Terrace > Block 6407/12 > Draugen Field > Rogn Formation (0.99)
- (21 more...)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- (2 more...)
Building the Case for Raw Seawater Injection Scheme in Barton
Flatval, Kirsti Berg (Shell Malaysia Exploration and Production) | Sathyamoorthy, Sekhar (Shell Malaysia Exploration and Production) | Kuijvenhoven, Cor (Shell International Exploration and Production B.V.) | Ligthelm, Dick (Shell International Exploration and Production B.V.)
Abstract Shell Malaysia Exploration & Production (SM-EP) is planning for secondary recovery via water injection in the Barton field by using the novel concept of raw seawater injection. Raw seawater injection is essentially injection of minimally treated, fully aerated seawater. The seawater having undergone limited solids interception only by coarse filtration. The concept of raw seawater injection has not received much interest from operators due to lack of understanding on issues such as reservoir souring and impact of oxygen on the reservoir. However, raw seawater injection has proven to be the most cost effective secondary recovery design for mature fields like Barton, which do not boast huge reserves. This paper will focus on work carried out to identify and mitigate additional risks from raw seawater injection, principally on issues of reservoir souring, increased corrosion on production system, increased levels of suspended solids and impact of oxygen on the reservoir scale. Raw seawater injection in Barton will be the first of its type in the Shell Group and only the second known attempt in the industry. Introduction The Barton field, operated by SM-EP, is located offshore North Sabah, approximately 220 km northeast of Labuan Island (Fig. 1). The water depth in this area is approximately 130 ft. The field is part of the North Sabah 96 Production Sharing Contract (PSC), which expires on 31/12/2019, with 50% SM-EP and 50% Petronas Carigali (PCSB) equity interest. The field came on stream in 1982, producing initially from jacket BTJT-A subsequently followed by production platform BTMP-B in 1989 (Fig. 2). The installations are unmanned with access by boat 4โ5 hours per day if weather allows. The field has been producing with gas lifting under natural depletion; with a reservoir drive mechanism dominated by solution gas drive aided by gravity segregation with moderate aquifer support. Current oil production is about 6 kbopd from 11 wells. Gas production, totalling some 3 MMscfd, is re-injected for disposal or used for gas lifting, with the excess flared at location. The reservoir pressure has decreased from 1058 to 550 psi over a period of 20 years. Most of the sand packages are near depletion. Geologically Barton reservoir is a heavily faulted asymmetrical anticlinal structure. The reservoir is compartmentalized into 4 separate blocks. The field is situated in a structural province characterized by intense compressional wrench tectonics and clay diapirism. Reservoir sands comprise of channels, crevasses, and shallow marine and delta front complexes with shale deposition in flood plain environment, which now form seals and flow barriers between sand units. Barton sandstones comprise predominantly of quartz, with minor content of feldspars, carbonate minerals and clays (mainly non-swelling type - kaolinite, chlorite and illite). Average porosity of the main sand package is about 20%, with rock permeability ranging from 100 mD to 5000 mD. The H sand unit has the highest rock permeability in the field. There are 3 sand packages in Barton:a.)Shallow D sands at 1000 ft tvdss charged with 16ยฐ API medium viscous oil, b.)F, G, H and I sands at 2000 ft tvdss charged with 32ยฐ API oil, and c.)Deeper M, P and Q sands at 3300 ft tvdss charged with 32ยฐ API oil. The current field STOIIP is about 165 MMstb, out of which some 50 MMstb has been produced. Production is almost exclusively from the G, H and I sands (main package). Fig. 3 shows the top structure map of H sand and cross sectional view of the field (along the North-South plane). The reservoir characteristic of the Barton field, and its current condition as a mature, relatively low-pressure field, makes it a good candidate for a secondary recovery project through pressure maintenance. Water injection was found to give the best results in terms of recoverable reserves and associated economics (Ref. 1) and is expected to add another 11 MMstb of reserves, increasing field recovery factor from 35% to 41%, and prolong field economic production life. Field reservoir pressure will be progressively increased to near initial condition (900 psia).
- North America > United States > Wyoming > Crook County (0.75)
- Asia > Malaysia > Sabah > South China Sea (0.75)
- Geology > Mineral > Silicate > Phyllosilicate (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.54)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.34)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.72)
- Water & Waste Management > Water Management > Lifecycle > Treatment (0.49)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 050 > Block 34/10 > Gullfaks Field > Statfjord Group (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 050 > Block 34/10 > Gullfaks Field > Lunde Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 050 > Block 34/10 > Gullfaks Field > Lista Formation (0.99)
- (7 more...)
Abstract Microbiologically Influenced Corrosion (MIC) is a well-documented phenomenon that involves microorganisms and affects multiple industries with untold economic impact. The most well- known microorganisms within the oilfield, by far, are Sulphate-Reducing Bacteria (SRB). It is thought that through SRB respiration, corrosion of metals can occur. An exact figure for MIC responsibility in overall corrosion is currently unknown. However estimates of between 10-50% are not uncommon, when coupled with estimated costs of metal corrosion in developed countries to be between 2-3% of Gross Domestic Product (GDP), suddenly the cost implications of MIC gain significance. The technical and economic implications have gained recognition within the oil and gas industry within the last thirty to forty years and monitoring techniques to detect microorganisms and corrosion have progressed and developed through increased interest in microorganisms commonly found within the oilfield. As with human nature, the ability to predict the future, rather than deal with the consequence is a preferred approach, which is one of the main driver's to pro-active monitoring techniques for detection of microorganisms to help determine the risk of MIC to occur, rather than a reliance on rate of corrosion alone. This approach has led to increased research in to the subject of oilfield microbiology and development of modern molecular techniques, often borrowed from other industries such as medical microbiology, that have come to the fore recently. However a significant focus on cost saving practices within the oil and gas industry has a significant and direct impact on the type and frequency of monitoring applied (if any). The objective of this review is to discuss and evaluate the available techniques and review the most common problems associated with microorganisms within the oil and gas industry. To determine effective monitoring practices in a practicable and economically viable manner to ensure monitoring can be carried out effectively, understood and evaluated while implementing control and mitigation strategies with confidence.
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Constituents > Bacteria (0.85)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Health, Safety, Environment & Sustainability > Environment (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)